NYSE:DNR NYSE:DNR

Barclays CEO Energy-Power Conference

September 6, 2016

NYSE:DNR 2

Cautionary Statements Forward Looking Statements: The data contained in this presentation that are not historical facts are forward-looking statements that involve a number of risks and uncertainties. Such forward-

looking statements may be or may concern, among other things, future hydrocarbon prices, the length or severity of the current commodity price downturn, current or future liquidity sources or

their adequacy to support our anticipated future activities, our ability to reduce our debt levels, possible future write-downs of oil and natural gas reserves, together with assumptions based on

current and projected oil and gas costs, current or future expectations or estimations of our cash flows, availability of capital, borrowing capacity, availability of advantageous commodity

derivative contracts or the predicted cash flow benefits therefrom, forecasted capital expenditures, drilling activity or methods, including the timing and location thereof, estimated timing of

commencement of CO2 flooding of particular fields or areas, or the timing of pipeline construction or completion or the cost thereof, dates of completion of to-be-constructed industrial plants

and the initial date of capture of CO2 from such plants, timing of CO2 injections and initial production responses in tertiary flooding projects, acquisition plans and proposals and dispositions,

development activities, finding costs, anticipated future cost savings, capital budgets, production rates and volumes or forecasts thereof, hydrocarbon reserve quantities and values, CO2 reserves

and their availability, helium reserves, potential reserves, percentages of recoverable original oil in place, the impact of regulatory rulings or changes, anticipated outcomes of pending litigation,

prospective legislation affecting the oil and gas industry, mark-to-market values, competition, long-term forecasts of production, finding costs, rates of return, estimated costs, estimates of the

range of potential insurance recoveries, changes in costs, future capital expenditures and overall economics, worldwide economic conditions and other variables surrounding our operations and

future plans. Such forward-looking statements generally are accompanied by words such as “plan,” “estimate,” “expect,” “predict,” “to our knowledge,” “anticipate,” “projected,” “preliminary,”

“should,” “assume,” “believe,” “may” or other words that convey, or are intended to convey, the uncertainty of future events or outcomes. Such forward-looking information is based upon

management’s current plans, expectations, estimates, and assumptions and is subject to a number of risks and uncertainties that could significantly and adversely affect current plans,

anticipated actions, the timing of such actions and our financial condition and results of operations. As a consequence, actual results may differ materially from expectations, estimates or

assumptions expressed in or implied by any forward-looking statements made by us or on our behalf. Among the factors that could cause actual results to differ materially are fluctuations in

worldwide oil prices or in U.S. oil prices and consequently in the prices received or demand for our oil and natural gas; decisions as to production levels and/or pricing by OPEC in future periods;

levels of future capital expenditures; effects of our indebtedness; success of our risk management techniques; inaccurate cost estimates; availability of and fluctuations in the prices of goods and

services; the uncertainty of drilling results and reserve estimates; operating hazards and remediation costs; disruption of operations and damages from well incidents, hurricanes, tropical

storms, or forest fires; acquisition risks; requirements for capital or its availability; conditions in the worldwide financial and credit markets; general economic conditions; competition;

government regulations, including tax and environmental; and unexpected delays, as well as the risks and uncertainties inherent in oil and gas drilling and production activities or that are

otherwise discussed in this quarterly report, including, without limitation, the portions referenced above, and the uncertainties set forth from time to time in our other public reports, filings and

public statements including, without limitation, the Company’s most recent Form 10-K.

Statement Regarding Non-GAAP Financial Measures: This presentation also contains certain non-GAAP financial measures. Any non-GAAP measures included herein is accompanied by a

reconciliation to the most directly comparable U.S. GAAP measure along with a statement on why the Company believes the measure is beneficial to investors, which reconciliation and

statement is included at the end of this presentation.

Note to U.S. Investors: Current SEC rules regarding oil and gas reserves information allow oil and gas companies to disclose in filings with the SEC not only proved reserves, but also probable and

possible reserves that meet the SEC’s definitions of such terms. We disclose only proved reserves in our filings with the SEC. Denbury’s proved reserves as of December 31, 2014 and December

31, 2015 were estimated by DeGolyer and MacNaughton, an independent petroleum engineering firm. In this presentation, we may make reference to probable and possible reserves, some of

which have been estimated by our independent engineers and some of which have been estimated by Denbury’s internal staff of engineers. In this presentation, we also may refer to estimates

of original oil in place, resource or reserves “potential”, barrels recoverable, or other descriptions of volumes potentially recoverable, which in addition to reserves generally classifiable as

probable and possible (2P and 3P reserves), include estimates of resources that do not rise to the standards for possible reserves, and which SEC guidelines strictly prohibit us from including in

filings with the SEC. These estimates, as well as the estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and are subject to

greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

NYSE:DNR 3

» CO2 enhanced oil recovery (“CO2 EOR”) is our

core focus

» We have uniquely long-lived and lower-risk

assets with extraordinary resource potential

» Owning and controlling the CO2 supply and

infrastructure provides our strategic advantage

» “We bring old oil fields back to life!”

Denbury’s Profile:

~6.7 Tcf Gross proved CO2 reserves

As of 12/31/2015

Over

1,100

miles of CO2

pipelines

2Q16 Tertiary Production

39,212

Bbls/d

2Q16 Total Production

64,506

BOE/d 890 Million Barrels (net)

EOR Resource Potential

Produced over

135 Million gross barrels from

EOR to date

2015 Proved Reserves

289 MMBOE ~98% oil

Operating Areas

A Different Kind of Oil Company

NYSE:DNR 4

Responding to Oil Price Volatility

Focus for 2016 Focus for 2016

» Reduce costs

» Optimize business

» Reduce debt

» Preserve cash and liquidity

NYSE:DNR 5

CO2 EOR Process

17%

18%

20%

Recovery of Original Oil in Place

(“OOIP”)

CO2 EOR (Tertiary)

Secondary (Waterfloods)

Primary

Remaining oil

(1) Based on OOIP at Denbury’s Little Creek Field

CO2 Oil Bank

Injected CO2 encounters trapped oil

Oil expands and moves toward producing well

CO2 EOR delivers almost as much production as primary or secondary recovery(1)

~

~

~

NYSE:DNR 6

U.S. Lower-48 CO2 EOR Potential

33-83 Billion of Technically Recoverable Oil(1,2)

(amounts in billions of barrels)

Permian 9-21

East & Central Texas 6-15

Mid-Continent 6-13

California 3-7

South East Gulf Coast 3-7

Rockies 2-6

Other 0-5

Michigan/Illinois 2-4

Williston 1-3

Appalachia 1-2

1) Source: 2013 DOE NETL Next Gen EOR. 2) Total estimated recoveries on a gross basis utilizing CO2 EOR.

Up to 83 Billion Barrels of Technically Recoverable Oil(1)(2)

NYSE:DNR 7

Up to 16 Billion Gross Barrels Recoverable(1) in Our Two CO2 EOR Target Areas

2.8 to 6.6 Billion Barrels

Estimated Recoverable in Rocky Mountain Region(2)

Denbury-operated fields represent ~10% of total potential(3)

3.7 to 9.1 Billion Barrels

Estimated Recoverable in Gulf Coast Region(2)

Existing or Proposed CO2 Source Owned or Contracted

Existing Denbury CO2 Pipelines

Denbury owned fields Proposed Denbury CO2 Pipelines

MT ND

TX

MS AL

WY

LA

1) Total estimated recoveries on a gross basis utilizing CO2 EOR, based on a variety of

recovery factors. 2) Source: 2013 DOE NETL Next Gen EOR 3) Using approximate mid-points of ranges, based on a variety of recovery factors.

NYSE:DNR 8

1) Proved tertiary oil reserves based on year-end 12/31/15 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated as of 12/31/14, using mid-point of ranges, based on a variety of recovery factors and long-term oil price assumptions.

2) Produced-to-date is cumulative tertiary production through 12/31/15. 3) Field reserves shown are estimated total potential tertiary reserves, using mid-point of ranges, including cumulative tertiary production through 12/31/15.

CO2 EOR in Gulf Coast Region

Jackson Dome

West Gwinville Pipeline

Citronelle

(2)

Tinsley

Martinville

Davis Quitman Heidelberg

Soso

Sandersville

Eucutta Yellow Creek

Cypress Creek

Brookhaven Mallalieu

Little Creek Olive

Smithdale McComb

Donaldsonville

Delhi

Lake St. John

Cranfield

Lockhart Crossing

Hastings

Conroe

Oyster Bayou

Thompson

Webster

Pipelines Denbury Operated Pipelines Denbury Proposed Pipelines

Free State Pipeline

~90 Miles Cost: ~$220MM

Green Pipeline ~325 Miles

Conroe(3) 130 MMBbls

Summary(1)

Proved 144

Potential 396

Produced-to-Date(2) 113

Total MMBOEs(3) 653

Houston Area(3)

Hastings 60 - 80 MMBbls Webster 60 - 75 MMBbls Thompson 30 - 60 MMBbls Manvel 8 - 12 MMBbls

158 - 227 MMBbls

Oyster Bayou(3) 20-30 MMBbls

Delhi(3) 45 MMBOEs

Tinsley(3) 46 MMBbls

Heidelberg(3)

44 MMBbls

Mature Area(3)

170 MMBbls

Summerland

Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

Manvel

Cumulative Production 15 – 50 MMBoe

50 – 100 MMBoe

> 100 MMBoe

Denbury Owned Fields – Current CO2 Floods

Denbury Owned Fields – Future CO2 Floods

Fields Owned by Others – CO2 EOR Candidates

NYSE:DNR 9

1) Proved tertiary oil reserves based on year-end 12/31/15 SEC proved reserves. Potential includes probable and possible tertiary reserves estimated by the Company as of 12/31/14, using approximate mid-points of ranges, based on a variety of recovery factors and long-term oil price assumptions.

2) Produced-to-date is cumulative tertiary production through 12/31/15.

CO2 EOR in Rocky Mountain Region

MONTANA

NORTH DAKOTA

SOUTH DAKOTA

WYOMING

Elk Basin

Shute Creek (XOM)

Lost Cabin (COP)

DGC Beulah

Riley Ridge (DNR)

Existing CO2

Pipeline

Pipelines & CO2 Sources

Denbury Pipelines Denbury Proposed Pipelines Pipelines Owned by Others Existing or Proposed CO2 Source - Owned or Contracted

Greencore Pipeline 232 Miles

~250 Miles Cost:~$500MM

~130 Miles Cost:~$225MM

Summary(1)

Proved 21

Potential 329

Produced-to-Date(2) 1

Total MMBOEs(3) 351

Bell Creek(3) 40 - 50 MMBbls

Hartzog Draw(3) 20 - 30 MMBbls

Grieve Field(3)

6 MMBbls

Cedar Creek Anticline Area(3)

260 - 290 MMBbls

Control of CO2 Sources & Pipeline Infrastructure Provides a Strategic Advantage

NEW JV Arrangement(4)

8/2016

15 – 50 MMBoe

50 – 100 MMBoe

> 100 MMBoe

Denbury Owned Fields – Current CO2 Floods

Denbury Owned Fields – Future CO2 Floods

Fields Owned by Others – CO2 EOR Candidates

Cumulative Production

3) Field reserves shown are estimated total potential tertiary reserves, using mid-point of ranges, including cumulative tertiary production through 12/31/15. 4) The revised agreement provides for the Company’s joint venture partner to fund the remaining estimated capital of $55 million to complete development of the facility and fieldwork in exchange

for a 14% higher working interest and a disproportionate sharing of revenue during the first 2 million barrels of production. Currently anticipate production start-up by mid 2018.

NYSE:DNR 10

Ample CO2 Supply & No Significant Capital Required for Several Years

1) Reported on a gross (8/8th’s) basis. 2) Estimated startup in late 2016. Volume estimates based upon preliminary projections from Mississippi Power.

Gulf Coast CO2 Supply Rocky Mountain CO2 Supply

LaBarge Area » Estimated field size: 750 square miles

» Estimated recoverable CO2: 100 Tcf

Shute Creek - ExxonMobil Operated

» Proved reserves as of 12/31/15: ~1.2 Tcf

» Denbury has a 1/3 overriding royalty interest and could receive up to ~115 MMcf/d of CO2 by 2021 at current plant capacity

Riley Ridge – Denbury Operated

» Probable CO2 reserves as of 12/31/15: ~2.8 Tcf(1)

» Future plans to construct a CO2 capture facility to develop significant CO2 reserves at Riley Ridge and in surrounding acreage

Lost Cabin – ConocoPhillips Operated » Denbury could receive up to ~50 MMcf/d

of CO2 at current plant capacity

Jackson Dome » Proved CO2 reserves as of 12/31/15: ~5.5 Tcf(1)

» Additional probable and possible CO2 reserves

as of 12/31/15: ~2.5 Tcf

» Currently producing at less than 60% of capacity

Industrial-Sourced CO2

» Air Products: hydrogen plant - ~40-50 MMcf/d

» PCS Nitrogen: ammonia products - ~20 MMcf/d

» Mississippi Power: power plant - ~160 MMcf/d(2)

NYSE:DNR 11

3.03 2.71

2.17

2.70

1.97 2.13

$-

$0.10

$0.20

$0.30

$0.40

$-

$1.00

$2.00

$3.00

$4.00

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16

-

200

400

600

800

1,000

1,200

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16

28% REDUCTION SINCE 1Q16

53% REDUCTION SINCE 1Q15

979

Total Company Injected Volumes (MMcf/d)

CO

2 C

ost

s p

er M

cf

1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE.

(1)

Significant Improvement in CO2 Efficiency

Industrial-sourced CO2

Jackson Dome CO2

762 678 705

634

459

CO

2 C

ost

s p

er B

OE

75%

25%

82%

18%

NYSE:DNR 12

1Q15 2Q15 3Q15 4Q15 1Q16 2Q16

G&A - Cash 5.69 4.66 3.91 3.02 5.29 3.33

Interest - Cash 6.92 6.90 6.85 6.74 7.08 7.35

Corporate Total

Production & Ad Valorem Taxes 3.42 4.43 3.19 3.33 2.72 2.90

Marketing Expenses 1.23 1.64 1.68 1.73 1.66 1.73

LOE 20.96 19.63 19.37 19.24 16.18 17.01

Field Level Total

Continued Improvement of Cash Costs

FIELD LEVEL CASH COSTS

CORPORATE CASH COSTS

$38.22 $37.26

15% REDUCTION SINCE 1Q15

$/BOE

$35.00 $32.93 $32.32

(1)

12.61 11.56 10.76 9.76 12.37 10.68

25.61 25.70 24.24 24.30 20.56 21.64

$34.06

25% REDUCTION SINCE FY2014

(2)

(1)(3)

Note: The numbers presented within this table may not agree to per-BOE data presented in our consolidated financial statements due to certain amounts not settled in cash. 1) Amounts presented exclude stock compensation. 2) Amounts include capitalized interest for all periods presented. In addition, interest expense during 2Q16 includes interest on our new 9% Senior Secured Notes, accounted for as debt for financial reporting purposes. 3) Amounts for 3Q15 exclude a reimbursement for a retroactive utility rate adjustment ($10 MM) and an insurance reimbursement for previous well control costs ($4 MM). 4) Amounts exclude derivative settlements.

44.45 54.69 44.20 38.99 29.76 42.02 Avg. Realized Price per BOE (4)

NYSE:DNR 13

PeerA

PeerB

PeerC

PeerD

DNRPeer

EPeer

FPeer

GPeer

HPeer

IPeer

JPeer

KPeer

LPeer

MPeer

NPeer

O

Operating Margin per BOE 23.74 21.66 20.68 20.59 20.22 16.78 16.07 15.84 15.72 14.39 14.33 13.66 13.53 10.11 9.97 2.83

Lifting Cost per BOE 11.63 8.34 5.68 8.36 21.80 10.81 9.16 11.51 11.08 11.67 7.15 18.05 13.34 8.39 10.38 7.59

Revenue per BOE 35.37 30.00 26.36 28.95 42.02 27.59 25.23 27.35 26.80 26.06 21.48 31.71 26.87 18.50 20.35 10.42

$-

$5

$10

$15

$20

$25

Top Tier Operating Margin

Source: Bloomberg and Company filings for period ended 6/30/2016. Peers include CLR, COP, CRC, CXO, DVN, MRO, MUR, NBL, NFX, OAS, OXY, PXD, RRC, SM, and WLL. 1) Operating margin calculated as revenues less lifting costs. 2) Lifting cost calculated as lease operating expenses, marketing/transportation expenses and production and ad valorem taxes. 3) Revenues exclude gain/loss on derivative settlements.

Peer Average

Highest revenue per BOE in the peer group

Upper Quartile

2Q16 Peer Operating Margins ($/BOE)

(1)

(2)

(3)

NYSE:DNR 14

Bank Credit Facility:

» $671 million in liquidity as of 6/30/16

» Basket for $1 billion of junior lien debt ($615 million issued to date)

» No near-term covenant concerns at current strip prices

Debt Reductions:

» 14% reduction in total debt since YE15

» 20% reduction in total debt since YE14

$545 Million – Total Principal Debt Reduction in 2016(2)

Ample Liquidity & No Near-Term Maturities(1)

$320 $221

$671 $615 $797

$622

2016 2017 2018 2019 2020 2021 2022 2023

$2,845

$3,310 $(443)

12/31/15 Total Debt Principal

6/30/16 Total Debt Principal(3)

Open-Market Debt

Purchases (net)

Bank Revolver Draw &

Other

Debt Exchanges

$(97)

$75

2021

$1,050 Undrawn

& Available

Drawn

Sr. Subordinated Notes Sr. Secured Bank Credit Facility Sr. Secured Second Lien Notes

2.8% 6.375% 5.50% 4.625% 9%

LC’s

Ample Liquidity & Significant Debt Reductions

Borrowing Base

12/31/14 Total Debt Principal

$3,571

$ In millions

In millions

(1) All balances presented as of 6/30/16. (2) Includes $5 million in debt reduction due to open-

market debt purchases made in July 2016. (3) Excludes $255 million of future interest payable on the

9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.

NYSE:DNR 15

Swap

s Significant Oil Hedge Protection

3Q16 4Q16 1Q17 2Q17 3Q17

WTI NYMEX Fixed-Price Swaps

Volumes Hedged (Bbls/d) 18,500 26,000 22,000 22,000 —

Swap Price(1) $38.96 $38.70 $42.67 $43.99 —

WTI NYMEX Enhanced Swaps

Volumes Hedged (Bbls/d) — — — — —

Swap/Sold Put Price(1)(2) — — — — —

Argus LLS Fixed-Price Swaps

Volumes Hedged (Bbls/d) 7,000 7,000 10,000 7,000 —

Swap Price(1) $39.61 $39.16 $43.77 $45.35 —

Argus LLS

Enhanced Swaps

Volumes Hedged (Bbls/d) — — — — —

Swap/Sold Put Price(1)(2) — — — — —

WTI NYMEX Collars

Volumes Hedged (Bbls/d) 4,500 — — — —

Ceiling Price/Floor(1) $71.22/$55 — — — —

Volumes Hedged (Bbls/d)(3) 4,000 4,000 4,000 — —

Ceiling Price/Floor(1)(3) $51.40/$40 $53.48/$40 $54.80/$40 — —

WTI NYMEX

3-Way Collars

Volumes Hedged (Bbls/d) — — — — 7,500

Ceiling Price/Floor/Sold Put Price(1)(2) — — — — $69.77/$40/$30

Argus LLS

Collars

Volumes Hedged (Bbls/d) 3,000 — — — —

Ceiling Price/Floor(1) $73.85/$58 — — — —

Volumes Hedged (Bbls/d)(3) 5,000 4,000 3,000 — —

Ceiling Price/Floor(1),(3) $53.74/$40 $55.79/$40 $57.23/$40 — —

Argus LLS

3-Way Collars

Volumes Hedged (Bbls/d) — — — — 1,000

Ceiling Price/Floor/Sold Put Price(1)(2) — — — — $69.25/$41/$31

Total Volumes Hedged 42,000 41,000 39,000 29,000 8,500

1) Averages are volume weighted.

2) If oil prices were to average less than the sold put price, receipts on settlement would be limited to the difference between the swap or floor price and sold put price.

3) Additional collars added during 2Q16.

Co

llars

Detail as of August 19, 2016

NYSE:DNR 16

2016 Capital Budget:~$200 Million

$55 MM

1) Includes capitalized internal acquisition, exploration and development costs and pre-production tertiary startup costs. Excludes capitalized interest estimated at $25 million.

64,000 - 68,000

$145 MM

2016 Capital Budget & Production Guidance

Development Capital Tertiary Delhi Other Non-Tertiary CO2 Sources & Other

$145

55 45 35 10

Capitalized Items(1) 55

Capitalized Items(1)

Development Capital

Production Update

Adjusted mid-point of 2016 production guidance from 66,000 BOE/d to 65,000 BOE/d due to non-core asset sales and weather-related impacts

Previous guidance 64,000 – 68,000

Weather-related shut-in production (est. annual impact)

(675)

Non-core asset sales (est. annual impact)

(500)

Adjusted guidance 64,000 – 66,000

BOE/d

» As of June 30, 2016, Denbury had 2,600 BOE/d of production shut-in that is uneconomic to either repair or produce

» Estimated 6-8% base production decline excluding shut-in production and weather-related downtime

NYSE:DNR 17

Update on Delhi Field NGL Plant

» Will extract NGLs from

our gas stream to be sold separately

» Will improve the Delhi flood with a purer CO2 recycle stream

» Will generate power used to offset electricity purchases

Benefits of the NGL Plant Focus for 2016 Benefits of the NGL Plant

Plant completion expected by the end of 2016

NYSE:DNR 18

Near-Term Focus

Our Advantages

Key Takeaways

» Reduce costs

» Optimize business

» Reduce debt

» Preserve cash and liquidity

Long-Term Visibility

» CO2 EOR is a proven process

» Long-lived and lower-risk assets

» Tremendous resource potential

Capital Flexibility

» Relatively low capital intensity

» Able to adjust to the oil price environment

Competitive Advantages

» Large inventory of oil fields

» Strategic CO2 supply and over 1,100 miles of CO2 pipelines

Appendix

NYSE:DNR 20

CO2 EOR is a Proven Process Significant CO2 Supply by Region

Gulf Coast Region » Jackson Dome, MS (Denbury Resources) » Port Arthur, TX (Denbury Resources) » Geismar, LA (Denbury Resources) » Mississippi Power (Denbury Resources) Permian Basin Region » Bravo Dome, NM (Kinder Morgan, Occidental) » McElmo Dome, CO (ExxonMobil, Kinder Morgan) » Sheep Mountain, CO (ExxonMobil, Occidental) Rocky Mountain Region » LaBarge, WY (ExxonMobil, Denbury Resources) » Lost Cabin, WY (ConocoPhillips) Canada

» Dakota Gasification (Cenovus, Apache)

Significant CO2 EOR Operators by Region

Gulf Coast Region

» Denbury Resources

Permian Basin Region

» Occidental » Kinder Morgan

Rocky Mountain Region

» Denbury Resources » Devon

» FDL » Chevron

Canada

» Cenovus » Apache

Jackson Dome

Bravo Dome

LaBarge Lost Cabin

DGC

McElmo Dome

Naturally Occurring CO2 Source

0

50

100

150

200

250

300

MB

bls

/d

Gulf Coast/Other

Mid-Continent

Rocky Mountains

Permian Basin

CO2 EOR Oil Production by Region(1)

1) Source: Advanced Resources International 2) Estimated startup in late 2016

Industrial-Sourced CO2

Port Arthur

Geismar

MS Power(2)

Sheep Mountain

NYSE:DNR 21

Actual Industry Recovery Curves

Range of Recovery 10%-18%

• An auditor’s view, Mike Stell, Ryder Scott, Permian Basin Study Group, April 4, 2011 • Reserve booking guidelines, Mike Stell, Ryder Scott, CO2 Conference, Midland December 8, 2005 • What is important in the reservoir, Richard Baker, Appega Conference, April 22, 2004

NYSE:DNR 22

Actual Curves – Denbury Mature Fields

Range of Recovery

11%-20+%

NYSE:DNR 23

Capital Structure

Debt ($ in thousands) 12/31/2015 Open-Market

Debt Purchases Other

Debt Exchanges(2) 6/30/2016

Senior Secured Bank Credit Facility 175,000 55,521 89,479 — 320,000

9% Senior Secured Second Lien Notes due 2021 — — — 614,919 614,919

Total senior secured debt 175,000 55,521 89,479 614,919 934,919

6⅜% Senior Subordinated Notes due 2021 400,000 (4,000) — (175,061) 220,939

5½% Senior Subordinated Notes due 2022 1,250,000 (42,255) — (411,033) 796,712

4⅝% Senior Subordinated Notes due 2023 1,200,000 (106,000) — (471,703) 622,297

Other subordinated notes 2,250 — — — 2,250

Total subordinated debt 2,852,250 (152,255) — (1,057,797) 1,642,198

Pipeline financings 211,766 — (4,318) — 207,448

Capital lease obligations 71,324 — (11,200) — 60,124

Total principal balance 3,310,340 (96,734) 73,961 (442,878) 2,844,689

Future interest payable on 9% Senior Secured Second Lien Notes due 2021(3)

— — — 254,660 254,660

Issuance costs on senior subordinated notes (32,752) 1,742 2,111 11,575 (17,324)

Total debt, net of debt issuance costs on senior subordinated notes

3,277,588 (94,992) 76,072 (176,643) 3,082,025

1) Includes $5.4 million in debt reduction due to open-market debt purchases made in July 2016.

2) Included in the exchange were 40.7 million shares of Denbury common stock.

3) Represents future interest payable on the 9% Senior Secured Second Lien Notes due 2021 accounted for as debt for financial reporting purposes.

Total Debt Principal Reduction YTD $545,014(1)

NYSE:DNR 24

$0

$50

$100

$150

$200

$250

$300

$350

4Q15 Bank Facility

Ending Balance

CapEx(2) Changes in Working &

Accrued Capital

Note Repurchases

$150

Cash Flow Covers CapEx

$(114)

2Q16 Bank Facility

Ending Balance

$175

$320

$(56)

$(103)

Capital Lease Payments & Other

Adjusted Cash Flow

From Operations(1)

$(22)

(In millions)

YE2016 Bank Facility

Estimated Ending Balance

$275 - $300

1) Cash flow from operations before working capital changes (a non-GAAP measure). See press release attached as exhibit 99.1 to the Form 8-K filed August 4, 2016 for additional information, as well as slide

32 indicating why the Company believes this non-GAAP measure is useful for investors.

2) Development capital expenditures, including acquisitions ($1 million) and capitalized interest ($12 million).

1H16 Change in Bank Credit Facility

NYSE:DNR 25

Commitments & borrowing base $1.05 billion

Redetermination Semi-annually – May 1st and November 1st

Maturity date December 9, 2019

Permitted bond repurchases Up to $225 million of bond repurchases (~$155 million remaining as of 8/3/2016)

Junior lien debt Allows for the incurrence of up to $1 billion of junior lien debt (subject to customary requirements) ($615 million issued to date as of 8/3/2016)

Anti-hoarding provisions If > $250 million borrowed, unrestricted cash held in accounts is limited to $225 million

Pricing grid

Senior Secured Bank Credit Facility Info

Financial Covenants 2016 2017

2018

2019 Q1 Q2 Q3 Q4

Total net debt to EBITDAX (max) N/A N/A 6.0x 5.5x 5.0x 5.0x 4.25x

Senior secured debt(1) to EBITDAX (max) 3.0x 3.0x N/A N/A N/A N/A N/A

EBITDAX to interest charges (min) 1.25x 1.25x N/A N/A N/A N/A N/A

Current ratio (min) 1.0x 1.0x 1.0x 1.0x 1.0x 1.0x 1.0x

Utilization

Based

Libor margin

(bps)

ABR margin

(bps)

Undrawn

pricing (bps)

X >90% 300 200 50

>=75% X <90% 275 175 50

>=50% X <75% 250 150 50

>=25% X <50% 225 125 50

X <25% 200 100 50

1) Based solely on bank debt.

NYSE:DNR 26

Production by Area

Average Daily Production (BOE/d) Field 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16

Mature area(1) 13,803 11,817 10,801 11,170 10,946 10,403 10,830 9,666 9,415

Delhi(2) 5,149 4,340 3,551 3,623 3,676 3,898 3,688 3,971 3,996

Hastings 3,984 4,777 4,694 5,350 5,114 5,082 5,061 5,068 4,972

Heidelberg 4,466 5,707 6,027 5,885 5,600 5,635 5,785 5,346 5,246

Oyster Bayou 2,968 4,683 5,861 5,936 5,962 5,831 5,898 5,494 5,088

Tinsley 8,051 8,507 8,928 8,740 7,311 7,522 8,119 7,899 7,335

Bell Creek 56 1,248 1,965 1,880 2,225 2,806 2,221 3,020 3,160

Total tertiary production 38,477 41,079 41,827 42,584 40,834 41,177 41,602 40,464 39,212

Gulf Coast non-tertiary 10,332 9,669 9,257 8,610 8,946 9,070 8,970 7,675 5,840

Cedar Creek Anticline 16,572 18,834 18,522 18,089 17,515 17,875 17,997 17,778 16,325

Other Rockies non-tertiary 4,862 4,850 4,750 4,433 4,115 3,880 4,292 3,434 3,129

Total non-tertiary production 31,766 33,353 32,529 31,132 30,576 30,825 31,259 28,887 25,294

Total production 70,243 74,432 74,356 73,716 71,410 72,002 72,861 69,351 64,506

Williston assets(3) (1,876) (1,744) (1,643) (1,561) (1,522) (1,473) (1,549) (1,364) (1,267)

Continuing production 68,367 72,688 72,713 72,155 69,888 70,529 71,312 67,987 63,239

1) Mature area includes Brookhaven, Cranfield, Eucutta, Little Creek, Lockhart Crossing, Mallalieu, Martinville, McComb, and Soso fields. 2) Beginning with the fourth quarter of 2014, average daily Delhi Field production amounts reflect the reversionary assignment of approximately 25% of our interest in that field effective November 1,

2014. 3) Includes non-tertiary production in the Rocky Mountain region related to the sale of remaining non-core assets in the Williston Basin of North Dakota and Montana, expected to close in the third

quarter of 2016.

NYSE:DNR 27

NYMEX Oil Differential Summary

Crude Oil Differentials

$ per barrel 2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16

Tertiary Oil Fields

Gulf Coast Region $7.86 $2.11 $(0.22) $2.04 $0.98 $(0.97) $0.60 $(1.95) $(0.98)

Rocky Mountain Region (14.24) (11.10) (2.09) (2.81) (1.30) (1.81) (2.74) (3.09) (2.43)

Gulf Coast Non-Tertiary 4.47 (0.28) (0.71) 0.68 0.58 (0.34) (0.19) (1.95) (3.16)

Cedar Creek Anticline (7.45) (9.78) (7.95) (6.48) (4.55) (3.08) (5.49) (4.82) (3.77)

Other Rockies Non-Tertiary (10.97) (12.03) (9.84) (8.48) (8.10) (6.91) (8.12) (8.90) (7.66)

Denbury Totals $2.62 $(2.21) $(2.81) $(0.89) $(0.96) $(1.74) $(1.55) $(3.02) $(2.18)

NYSE:DNR 28

25.68

23.26 23.17 22.64

21.08 19.70 19.43 19.31

16.23 17.04

1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16

Significant Reductions in LOE

12/31/14 $53.27

WTI Price $/BBL

Recurring LOE(1)

$/BOE

12/31/13 $98.42

12/31/15 $38.34

1) Recurring lease operating expenses (“LOE”) presented in this slide exclude certain non-recurring items, including a reimbursement for a retroactive utility rate adjustment ($10 MM) and an insurance reimbursement for previous well control costs ($4 MM) for 3Q15, well control costs ($3 MM) for 4Q14, insurance reimbursement net of additional well control costs ($10 MM) and Riley Ridge workover cost ($8 MM) for 3Q14, and Riley Ridge workover cost ($4 MM) for 2Q14.

6/30/16 $48.33

2/11/16 $26.21

NYSE:DNR 29

Analysis of Total Operating Costs

Total Operating Costs $/BOE

2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16

CO2 Costs $3.73 $3.79 $3.03 $2.71 $2.17 $2.70(1) $2.66 $1.97 $2.13

Power & Fuel 5.36 5.93 5.88 5.28 5.77 5.43 5.59 5.26 5.02

Labor & Overhead 5.59 5.44 5.45 5.33 5.25 5.23 5.31 5.09 5.22

Repairs & Maintenance 1.33 1.45 1.44 1.22 1.27 1.41 1.33 0.80 0.73

Chemicals 1.61 1.37 1.14 1.23 1.11 1.08 1.14 0.97 0.90

Workovers 4.74 4.23 2.71 2.41 2.31 2.16 2.40 1.22 1.99

Other 1.69 1.89 1.43 1.52 1.55 1.30 1.45 0.92 1.05

Total Normalized LOE(2) $24.05 $24.10 $21.08 $19.70 $19.43 $19.31 $19.88 $16.23 $17.04

Special or Unusual Items(3) 4.45 (0.26) --- --- (2.09) --- (0.51) --- ---

Total LOE $28.50 $23.84 $21.08 $19.70 $17.34 $19.31 $19.37 $16.23 $17.04

Oil Pricing NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56

Realized Oil Price(4) $100.67 $90.74 $46.02 $56.92 $45.74 $40.41 $47.30 $30.71 $43.38

1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.46 per BOE. 2) Normalized LOE excludes special or unusual items, but includes $12MM of workover expenses at Riley Ridge during 2014. 3) Special or unusual items consist of Delhi remediation charges of $114MM in 2013, Delhi remediation charges, net of insurance reimbursements of ($7MM) in 2014, and a

reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM) in 3Q15. 4) Excludes derivative settlements.

NYSE:DNR 30

Analysis of Tertiary Operating Costs

Tertiary Operating Costs $/Bbl

2013 2014 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16

CO2 Costs $6.82 $6.87 $5.39 $4.69 $3.79 $4.72(1) $4.65 $3.38 $3.51

Power & Fuel 6.64 7.46 7.30 6.27 6.81 6.53 6.72 5.98 5.62

Labor & Overhead 4.95 5.04 5.03 4.89 4.60 4.72 4.81 4.54 4.18

Repairs & Maintenance 0.98 0.90 1.15 0.86 0.97 1.09 1.02 0.71 0.77

Chemicals 1.64 1.36 1.07 1.24 1.03 1.06 1.10 0.96 1.06

Workovers 4.03 3.15 2.06 2.00 1.73 1.61 1.85 0.85 2.04

Other 0.45 0.90 0.70 0.57 0.69 0.52 0.62 0.47 0.50

Total Normalized LOE(2) $25.51 $25.68 $22.70 $20.52 $19.62 $20.25 $20.77 $16.89 $17.68

Special or Unusual Items(3) 8.12 (0.47) --- --- (3.64) --- (0.90) --- ---

Total LOE $33.63 $25.21 $22.70 $20.52 $15.98 $20.25 $19.87 $16.89 $17.68

Oil Pricing NYMEX Oil Price $98.05 $92.95 $48.83 $57.81 $46.70 $42.15 $48.85 $33.73 $45.56

Realized Oil Price $105.88 $94.65 $48.52 $59.63 $47.56 $41.13 $49.27 $31.70 $44.46

1) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.80 per Bbl. 2) Normalized LOE excludes special or unusual items. See (3) below. 3) Special or unusual items consist of Delhi remediation charges of $114MM in 2013, Delhi remediation charges, net of insurance reimbursements of ($7MM) in 2014, and a

reimbursement for a retroactive utility rate adjustment ($10MM) and an insurance reimbursement for previous well control costs ($4MM) in 3Q15.

NYSE:DNR 31

CO2 Cost & NYMEX Oil Price

Q110

Q210

Q310

Q410

Q111

Q211

Q311

Q411

Q112

Q212

Q312

Q412

Q113

Q213

Q313

Q413

Q114

Q214

Q314

Q414

Q115

Q215

Q315

Q415

Q116

Q216

Tax 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.02 0.02 0.02 0.02 0.02 0.02 0.03 0.03 0.04 0.03 0.02 0.03 0.04 0.04 0.04 0.05

Purchases 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.16 0.16 0.24 0.22 0.27 0.27 0.23 0.28 0.26 0.19 0.16 0.16 0.15 0.15 0.15 0.2

OPEX 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.07 0.06 0.07 0.1 0.08 0.1 0.1 0.11 0.1 0.1 0.11 0.13 0.12 0.17 0.11 0.13

NYMEX Crude Oil Price 78. 78. 76. 85. 94. 102 89. 93. 102 93. 92.3 88.2 94.4 94.1 106 97.6 98.6 103 97.3 73 48.8 58 46.7 42.2 33.7 45.6

$0

$10

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$0.00

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NY

ME

X C

rud

e O

il P

ric

e / B

bl

CO

2 C

osts

/ M

cf

(2)

(1

)

0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 10% 4% 14% 12% 16% 14% 15% 15% 22% 18% 23% 22% 23% 25% Industrial-Sourced CO2 %

3Q 10

2Q 10

1Q 10

4Q 10

2Q 11

1Q 11

4Q 11

3Q 11

2Q 12

1Q 12

4Q 12

3Q 12

2Q 13

1Q 13

4Q 13

3Q 13

2Q 14

1Q 14

4Q 14

3Q 14

2Q 15

1Q 15

4Q 15

3Q 15

1Q 16

2Q 16

1) Excludes DD&A on CO2 wells and facilities; includes Gulf Coast & Rocky Mountain industrial-source CO2 costs. 2) CO2 costs in 4Q15 include workovers carried out at Jackson Dome of $3 million, or $0.05 per Mcf.

NYSE:DNR 32

Non-GAAP Measure

Reconciliation of cash flows from operations (GAAP measure) to adjusted cash flows from operations (non-GAAP measure)

Adjusted cash flows from operations is a non-GAAP measure that represents cash flows provided by operations before changes in assets and liabilities, as summarized from the Company’s Unaudited Condensed Consolidated Statements of Cash Flows. Adjusted cash flows from operations measures the cash flows earned or incurred from operating activities without regard to the collection or payment of associated receivables or payables. Management believes that it is important to consider this additional measure, along with cash flows from operations, as it believes the non-GAAP measure can often be a better way to discuss changes in operating trends in its business caused by changes in production, prices, operating costs and related factors, without regard to whether the earned or incurred item was collected or paid during that period.

2015 2016

Q1 Q2 Q3 Q4 Q1 Q2

Cash flows from operations (GAAP measure) $138 $289 $273 $165 $2 $61

Net change in assets and liabilities relating to operations 58 (37) (30) (36) 55 32

Adjusted cash flows from operations (non-GAAP measure) $196 $252 $243 $129 $57 $93

In millions